Q2 2019 Earnings Call

Morning.

My name is Dan and I will be your conference operator today.

At this time I'd like to welcome everyone to the second quarter 2019 earnings release and operations update for Oasis petroleum.

All participants will be in listen only mode.

Should you need assistance. Please signal a conference specialist by pressing the star key followed by zero.

After todays presentation, there will be an opportunity to ask questions to ask a question you May Press Star then one on your Touchtone phone.

To withdraw your question. Please press Star then two please note. This event is being recorded.

I will now turn the call over to Michael Lil Oasis Petroleum CFO to begin the conference. Thank you you may begin your conference.

Thank you Ben good morning, everyone.

Today, we are reporting our second quarter 2019 financial and operational results.

We're delighted to have you on our call.

I'm joined today by Tommy News, and Taylor Reid as well as other members of the team.

Please be advised that our remarks on both a wet petroleum and Oasis midstream partners.

Including the answers to your questions include statements that we believe to be forward looking statements.

Within the meaning of the private Securities Litigation Reform Act.

These forward looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently disclosed in our earnings releases and conference calls.

Those risks include among others.

Matters that we have described in our earnings releases as well as in our filings.

With the Securities and Exchange Commission, including our annual report on Form 10-K , and our quarterly reports on Form 10-Q .

We disclaim any obligation to update these forward looking statements.

During this conference call, we will make reference to non-GAAP measures and reconciliations to the applicable GAAP measures can be found in our earnings releases.

And on our website.

We will also reference our current investor presentation, which you can find on our website.

With that I'll turn the call over to Tommy.

Good morning, and thanks for joining our call. The Oasis team continues to execute on our plan harvesting free cash flow from the lowest end to fund the Permian development and generate free cash flow at the M. P level, excluding the impact impact of O M P.

As an organization, we continue to focus on pershare value drivers of cash flow.

Cash margins return on investment capital efficiency and volume performance relative to our budget targets.

All of which should drive attractive returns, whether at the well project or corporate level.

Taylor will get into more operational detail in a minute, but I want to highlight a few key points about our performance and strategy.

First the laces continues to execute its measured development program in 2019, and expects to generate strong free cash flow at the M. P level at current oil prices.

Second in the Williston in spite of some challenging weather and flooding conditions, we executed well on the DNC side.

Getting 20, 124 wells online during the second quarter, albeit waited to the last latter part of the quarter.

Third in the Delaware.

We've been able to secure services and drive operational efficiencies good to get visibility on take away capacity and we continue to make significant progress delineating our position and understanding the subsurface.

We brought on three wells testing the Wolfcamp, a b and C across our position. We also completed three other wells during the quarter and our sugar low spacing unit testing our spacing concepts.

In the Wolfcamp, a upper and lower.

These latter three wells were fracked in the second quarter and came on production early July so keep in mind that while the Capex was spent in the second quarter they'll show up at our July completion count.

Additionally, we were able to do a small bolt on acquisition in Ward County that created a 1200 80 acre spacing in it.

In fact, all of this puts us in a position now to move towards development mode.

Fourth our midstream assets continue to provide an advantage. This can be seen in our cost structure net backs and flow assurance as we said for some time the midstream side of the business has been a big win for us in a very important component of managing business risk over the last several years as all of our drilling was focused on wild basin.

We IPO the Oasis midstream partners, almost two years ago, and it's proven to be one of the better performing partnerships in a difficult market.

We continue to look at ways to enhance the value.

Of our ownership in this asset.

During the quarter, we did experience some downtime in the wild basin gas complex.

The impact reduced quarterly production by approximately 3000 be at least per day net in the second quarter.

We will also have some impact in early July that's captured in our guidance. The complex has been up and running well since mid July .

Over and over the last few weeks that coupled with assessing the production from our second quarter completions really starting to show up now and total O US Oasis production, averaging about 89000 Boe per day in July .

We continue to incorporate our views are well performance completion timing and any infrastructure constraints into our full year guidance and have updated our range to 86.8.

88.5 thousand be always.

Per day to account for our current views.

We're now estimating third quarter volumes to range between 87 to 90000 Boe per day with an oil cut of around 71.5%. We continue to expect the fourth quarter oil cut to trend down a little bit about 71%.

With things moving around a bit on us here.

It's early to begin totally flushing out 2020.

Well, we would expect both oil and total volumes to be roughly flat to up relative to our fourth quarter exit rate, depending on oil price, our cash flow generation and operations plan.

Additionally, weve updated slide seven of our presentation to reflect our latest free cash flow projections.

We have updated our capital assumptions as you saw in our press release, the the increase primarily reflects an adjustment to deflation expectations related to a lower crude price in our budget assumptions improve cycle times in the Delaware basin, resulting in increased budge with a two rig program and the number of operated wells with higher working interest as well as increased non op spending and the highest return parts of the Wilson basin.

All of this results in an increase in capex, but that's more than covered by our free cash flow generation.

On the EBITDA side, we've adjusted for pricing year to date made tweaks to our volume forecast and lower natural gas and NGL pricing, we now expect to generate $75 million to $120 million or free cash flow at the MP business in 2019, and a 50 to $60 a W.T.I. price.

Our intent at this point would be to take excess cash to our revolver as we've talked about in the past.

Despite a few headwinds Oasis E M. P stands to deliver strong free cash flow this year.

The underlying business remains strong and we continue to advance our strategic objectives, which include side and size and scale.

Portfolio diversity asset quality and financial strength with that I will turn the call over to Taylor.

[noise] [noise] thanks Tommy.

We continue to execute our 2019 program with the focus on efficient operating in a Wilson and preparing the Delaware for full field development.

Boy says well productivity and Wilson remain the top of the pack.

As seen on slide 10 of our Investor deck. We're ranked number two for the 12 month cumulative average oil equivalent versus our peers.

[noise] separately.

We continue to be encouraged by delineation results from step out areas.

Slides eight and nine have been updated to reflect the latest data from select emerging areas in the World then.

We continue to see outstanding results and it would north Alger.

South Cottonwood.

In Red Bank, which shows that these areas are competitive with the rest of the basin.

And painted woods, we provided additional production history, which validates our view that the area of highly productive with the low economic breakeven.

The remaining inventory in these areas.

Averages between seven and 10 wells per spacing.

When combined with current well costs these well performance numbers lead to greater economics across the play.

Current well cost, where the Bakken averaged about $7.6 million and we see a path to work these down to $7 million by the end of the year.

[noise] switching to the Delaware, we're seeing strong performance across the entire column.

Certainly wolfcamp B and C wells performing in line with the Wolfcamp Bay.

We recently brought on a wolfcamp b the rattlesnake, one age with one month cumulative oil production of 3500 barrels per thousand foot of lateral.

[noise], a recent wolfcamp C well occur when a woman age delivered three month cumulative oil production of 7500 barrels per thousand foot of lateral.

Additionally, we brought on a three well wolfcamp a spacing test in early July .

As a reminder, we will be conducting a larger eight well spacing tests.

Which we're currently drilling expect to bring online and 2020.

[noise] learned a tremendous amount since closing on the forge asset in early 2018.

We've been able to secure services at a reasonable cost.

Execute on her well program.

Navigate the volatile basis pricing and develop an effective marketing strategy, which will command attractive pricing.

Our subsurface knowledge is growing rapidly to oasis wells.

Non operated activity.

Trading information with other partners and third party data sources.

[noise] cycle times are improving rapidly as well as we begin to discuss last quarter. We've made significant strides in reducing our drilling days with our most recent two mile lateral wells being drilled in the 25 to 30 day range versus our first wells in the basin that were under 40 plus day range.

This has allowed us to drill more wells this year than originally planned.

We continue to expect completions of nine to 11 wells for the year.

As always our focus remains on optimal optimizing capital efficiency.

Well, we could drop a rig to forego these additional wells and the associated spending in 2019.

[noise], keeping an official crew together and continuing to lower well cost is important.

The fact that we are moving into development development with more DS you drill out.

Means that we will carry a little larger DUC backlog than what we were in in testing mode. When we were drilling one to three well pad.

Additionally, we are funding these additional wells with free cash flow generated in 2019.

Said another way you p. free cash flow will be slightly less this year.

But the benefits of having an efficient program with manageable cycle times are a net positive for the company.

[noise] drilling speed should continue to improve as well as we optimize well design and shift to pad development.

In development mode, We would expect to drill times to be in the mid to low twentys.

And we're targeting well cost of $9.6 million for a four well pad.

Which compares to approximately 11 and a half a million dollars in 2018.

We've learned a great deal sensitive grading this world class asset about 18 months ago.

Well performance remains exceptional and we've been able to lower cost significantly.

We continue to believe economics will be as good as or potentially better than the best parts of the world.

To close we continue to execute on our 2019 plan focused around an efficient Wilson program as we move into development in the Delaware.

Oh, it's as benefits from our inventory debt subsurface expertise.

Operational experience as well as the top notch marketing team.

We're excited about driving these assets forward into 2019 and beyond.

With that ill now turn the call over to Michael.

[noise]. Thanks Taylor.

Oh, it's just remains focused on delivering our 2019 program operating costs are in check and oil realizations remained strong.

We are on a trajectory to deliver significant free cash flow in 2019.

We continue to enjoy strong liquidity levels with the total total borrowing base of $1.6 billion.

With only 531 million drawn as of June Thirtyth 2019.

Oh I just had a net debt in the second quarter annualized EBITDA multiple of 2.7 times with adjusted EBITDA attributable to a waste this approximating.

$238 million in the second quarter.

Turning to midstream, we continue to work towards executing final agreements.

For the dedication of certain Delaware acreage to NPV a painter devco.

We would expect this to be finalized September 1st.

Additionally, a waste is continues to work with third parties for gas infrastructure in the Delaware and expects to provide an update in the coming months on the outcome of the selection process.

[noise] total midstream Capex was adjusted to range or $219 million to $230 million. This largely largely reflects additional third party business.

Incremental plant cost and an acceleration of gathering infrastructure construction spending from 2020 into 2019.

Net capex still waste is attributable to its retained interest is expected to range between 15 and $16 million.

Well be talking in more detail on the LMP call shortly and I would direct you to our own P. press release for more color on our continued success on the midstream.

We have approximately 80% of the remainder 2019 estimated oil production hedged at a weighted average floor price of $56 per barrel.

[noise] for 2020, we've added additional collars and swaps the details of which can be found in the appendix in the appendix of our investor presentation.

[noise] Wilson crude differentials remained strong as our marketing team has done a great job of being opportunistic and getting Oasis superior realizations.

In the Delaware as expected crude differentials have narrowed considerably versus last year and several new long haul pipes coming online in the back half of 2019 should continue to improve realizations.

We took down the top end of our differential guidance range and we're now expecting $1.50 to $3 per BOE later in 2019.

As everyone is aware natural gas and NGL prices have deteriorated significantly since may.

A waste as benefits from its midstream assets and was an early mover in securing strong contracts with third parties to process and market our Ngls.

This should keep our pricing.

Ralph relatively towards the top end of our peer group.

However, on an absolute basis gas and NGL realizations have come down significantly and for modeling purposes.

We've begun to providing differential guidance on a two stream basis.

To sum things up awareness continues to execute well and we're in a strong position to deliver in 2019 and beyond.

With that I'll hand, the call back over to Ben for questions.

Thank you we will now begin the question and answer session to ask a question you May Press Star then one on your Touchtone phone.

If you are using a speakerphone. Please pick up your handset before pressing the keys to answer your question. Please press Star then to you.

At this time, we will pause momentarily to assemble our roster.

Our first question comes from Derrick Whitfield with Stifel. Please go ahead.

Thanks, and good morning all.

One is there.

Perhaps for Michael referencing slide seven of your presentation. It's I don't recall based on past conversations on this slide your views on potential free cash flow outcomes for 2019.

Contemplated 50 million of the $80 million increase just announce for upstream capex.

Could you confirm that and possibly walk us through any other material changes in your Q2 versus Q1 assessment.

Yeah, no. It's a great question Derek I really appreciate that.

Yes, absolutely right. So what we talked about at the beginning the year remember we were in a.

Mid $40 oil price when we budgeted for the year as we came out in February with that that budget, we talked about a a budget at $50 and we came out with a capex number and in that cash flow chart and through many discussions with you and with others, we talked about in a $60 environment.

You wouldn't see the same type of deflation that you would see in a $50 environment.

And so we did have in that free cash flow chart at 60 $50 million more essentially for the lack of deflation at the same pace that we would have saw in the $50 environment.

Where are you seeing oil prices. So far this year activity level has it really been more in the $60 level and thankfully, we've we've been closer to that that level in terms of pricing. We've enjoyed that free cash flow, but service costs have remained a bit higher now you're seeing a lot of progress that we're making.

Not quite as quickly is that $50 scenario.

But you are seeing well costs come down.

Across both basins in and we think we can continue to hold that you're seen service costs starting to soften now, but so just a little bit different and we've taken the deflation assumptions out of.

Out of those Capex numbers that weve, just newly guided to.

Oh, so those are kind of the differences obviously on the free cash flow side, you're also seeing some adjustments on the NGL and natural gas side, we talked about significantly lower realizations on that side, there's probably about $30 million a difference from.

Kind of what we had in in that free cash flow before versus where differentials and pricing is today.

So you're seeing that impact that number as well.

That's great. Thanks for the confirmation and then perhaps for yourself for Tommy.

There has been drawing discussion within the Investor community regarding the long term strategic fit of your midstream business.

As I recall from my comments last quarter, the upstream business has derive tremendous benefit from Isis having control of the infrastructure.

However, you guys did note that its strategic importance is evolving.

Big picture. If you were to think about the amount of expected gas processing additions in the Bakken in the second half.

And your progress in the Delaware to date.

How do you currently view the strategic importance of that business.

Yes.

Let me make a comment there I'll turn it over to Taylor that.

You know as we went into the downturn, we kinda contracted to.

Activity in Wild basin in that asset was.

The really really important to us.

To be able to move our volumes as you know.

No and till that gas plant came on gas production in the basin was 2.8 Bcf a day.

Processing capacity two Bcf a day and then our plant came on plant two.

And bumped that up to 2.2 Bcf a day.

And so we've we've been very fortunate in that we've been able to absent the.

The little Blip, we had here in June early July we have been able to move our volumes, which has been tremendously important to us.

But as we start to look at.

In the future and and more activity.

In areas outside of Wild basin, which.

Based on the slide in the presentation, you can see a lot of those areas.

Have really improved over the last few years in terms of results.

That more of our drilling activity.

We'll move move out of Wild basin.

So that asset.

Won't be quite as strategic to us on a go forward basis as it as it has been in the past Taylor.

Yes, what I would add to that is you know.

If you look back in 2015 2016, you'll remember that was when we really.

We're spending a lot of.

Dollars developing the midstream on the gas side building the plant is building out the wild basin infrastructure.

And as Tommy said it was super strategic at the time, because the oil <unk> gas capture laws.

Wanted to make sure we had that infrastructure in place and as we are doing that.

Obviously in a downturn.

Being very cautious about where were spending our dollars and with a focus on being free cash flow positive.

We.

We're very open about considering alternatives for.

Those investments was there a different way to fund that very important spend for us.

And and we had a lot of conversations with you guys around that you know at the time.

A little more kind of challenging to.

To find those dollars, especially for a really a nascent business that.

We're just getting off its fee and.

The good news is you know if you fast forward to today.

Yes, it is a substantial business.

It is it is differential in terms of a first mover up in the basin on on building out gas infrastructure.

And in the cash flows and.

And value in the business has materialized still growing.

Great coverage ahead of us.

And so the great news around that is.

That theres theres really big value it.

And into Tommy's point about.

How do you think about it strategically is still very important to us but.

The.

The biggest strategic piece of it that we wanted to get set up and get it in place is been served.

At this point so you know as we go forward and.

And think about that investment in the value in it.

You know people asked Hey, Jude.

Would you would you ever consider doing anything with that.

We're open to alternatives and and will consider.

Consider all those things and we want to maximize value for the company and so.

We will be thinking about all the things going forward, but at the end of the day. It's you know what we.

Well, we try to build his coveted assets.

And this has been a coveted asset for us and I think it would be a coveted asset for a for a lot of other people as well.

But that's what we try to do across the board across our entire portfolio.

Is build a coveted assets and and we certainly think this is one of them.

Thanks, Tom until it's very helpful guys.

You bet.

Our next question comes from Michael Hall, with Heikkinen Energy Advisors. Please go ahead.

Thanks, I appreciate it guys.

I was just curious I guess, a little bit on the Delaware program better understanding.

Kind of the moving pieces there that.

Changed a little bit.

How do you think about kind of as you building up.

Sounds like a little bit of a of an incremental backlog.

From a completion standpoint.

How big of what it what does the DUC count look like I guess as you head out of the year and.

Is that really like you alluded to really more a function of.

Just kind of optimizing for the the changing pad size versus.

Providing some sort of future potential drawdown potential that would have an improved capital efficiency 2020.

Michael It you know, it's really probably a little bit of both.

You know if we if we've been talking about the DUC backlog when we're drilling.

But at this point, we're really doing kind of one to three well pad and.

Having a single digit backlog was was natural with that.

With they pre cycle times that we've talked about keeping the two rigs going.

No you're likely to build to low to.

Might be the low to mid teens next year.

And so it does two things one it.

Yeah, we're on an eight well pad right now the one that behind it is likely to be somewhere in that kind of range as well.

And then so you're going to need a little bit more of a.

DUC backlog, if you're going to drill eight wells before you Frac them and then follow with another one for you. So you just need a little bit more of a pad.

But there is there is some additional build up there that gives us the flexibility next year, depending on how things are going to.

To draw that down a bit and so will you know as we get into 2020, we will be looking.

At all those options you know, what's what's that right level would you pull it down a bit more.

From a capital efficiency standpoint, like you talked about.

Okay and can you remind me what the kind of required activity levels look like from a lease capture standpoint, and the Delaware.

And Tony Tony.

Yeah, it's been.

It's kind of a one and a half.

It depends on.

Cadence from kind of one and a half rig.

To meet her for her land holding requirements and most of that is.

You talked about about 70% of that is on.

Of our land is on the Delaware and we've got a.

No a great agreement there that allows us to.

We can we can draw in development mode and as you know it holds the pool bankers, who will have to be jumping all around and it really helps from a efficiency standpoint.

Okay. That's helpful. And then last one of mine as you mentioned in the prepared remarks that.

I think it was you Michael that you see potential room to take a Williston basin, well costs down closer to $7 million.

In the back half is that something that's already played into the updated budget or would that.

Would that be I guess, a potential tailwind in the back half of the year.

Yeah, I really at this point Weve kind of factored in the costs that we you know the seven six range that.

We're talking about Michael and so that you could provide a bit of a bit of a tailwind dependent on how well we did.

Okay.

I appreciate the time guys. Thank you.

That Michael.

Our next question comes from Ron Mills with Johnson Rice. Please go ahead.

Good morning, guys quick question following on the Delaware.

You talked a little bit maybe about the spacing test you you did I know you just came on in July what kind of spacing was was that done on and then when you move and I think you said you're doing an eight well spacing test now is that is the second spacing test designed to do just not just the upper and lower age, but but also the the b and C. On the on the same pad.

Yes.

Right good question.

The first test the three well tests.

It was all in Wolfcamp, a and so we we actually had to lower Wolfcamp, a wells and one upper wolfcamp a well the.

The spacing the two lower wells were 800 feet apart.

And then the the upper wells right smack in between a minute.

It was about a 200 feet above them. So it's like a wine rack you Adam that one right in the middle but 200 feet above up in the upper Wolfcamp, a and then horizontally with 400 feet from.

Goes lower Wolfcamp wells.

And.

In terms of the eight well test that's coming up.

It's going to be a combination a third bone spring sand.

And a wolfcamp a test that will have.

Four wells in the third bone spring in a four wells in the lower Wolfcamp a.

So at this point, it's not a.

We're looking at that going forward, we don't have B and C.

Incorporated in the multi world.

But as we talked about we've got a number of.

Really attractive BMC tests that were excited about so we're looking at incorporating.

More of the column.

As we go down the road.

Okay, Great and then Michael just for you on the on the Slide Seven chart I know the new presentation updates for the for the New Capex you still have kind of an EBITDA number based on.

On 50 dollar.

Oil prices. So you you you seem to be burdening to capex with with the higher capex level.

So, but what kind of impact do you does that $10 Delta Avenue in the EBITDA because is it as simple as it's kind of that 25 or 30, my 30 million dollar.

Delta.

As shown on the far right.

Hey, I just wanted to try to make sure I understand the.

You do have an associated EBITDA benefit from the higher prices, even though it does impact spending.

Correct or not that's absolutely right Ron.

And that is a good way to look at at this point the free cash flow numbers now have the same have the same capital.

Assuming that kind of higher cost level kind of throughout the year. So.

Is there a possibility that you could bring it down if you sat at 50 and today, where the strip is closer to 50 for a longer period of time.

Possibly but.

Right now this has kind of the.

The less deflation case kinda in there.

And the way to think about the differences with hedges and all of that impact.

Is that difference in the free cash flow line kind of midpoint of 85 to the midpoint of 115.

So that that $30 million number you're referencing is kind of the differential between those scenarios.

Great. Thank you guys.

Thanks, Rob.

Our next question comes from Brad Heffern with RBC capital markets. Please go ahead.

Hey, good morning, everyone.

Just looking at the New guide and what the Threeq you guys.

The Threeq guide implies for Fourq you. It looks like production is expected to be down a little bit and there is only expected to be around 100 million in Capex I was just wondering if.

If those two things are related and what it says about the momentum into 2020.

So.

When you when you look at the production like you said it is.

If it is going to taper down a little bit in fourth quarter, and then it's really a.

It's just really everything income coming together and you know we look every quarter, we look at everything from our PDP base do you know the capital wells coming on line.

Capital well performance and so as we.

As we look into.

For Q of this year, we think that.

That that number was down a bit really.

Sets us up for a for 2020.

One of the things that.

Let's say is.

From a from a PDP standpoint.

As we continue to look at our ER volumes one of the things we talked about in the past and then in factored in a bit here is.

We've talked about spacing and if you look at our pre 19 wells.

And this is really a focus.

In Wild basin.

We tended to be a little tighter.

When we drilled the very first wells there were in kind of 13 to 14 well per spacing unit range, then we walk that down over time.

Everything 19 forward is.

And really going back into parts of 18, we are 18, we really made this shift but everything going forward is.

Under this 10 10 to 11, well spacing and we think were spaced about right. At this point you know the the impacts of the tighter spacing.

We think we have fully factored in and have that behind us as we go forward, but all all that stuff kind of.

Plays into.

Into the number for Fourq you as we dial it in and then the last thing I'd say in terms of.

Cadence, which which you touched on.

Our capital when you when you look at three to you in Fourq you.

Did it's going to be still weighted a little bit more with the remaining capital we have for the year, probably about 60% to 65% of that is going to be in Threeq, you and then the balance will be in fourq. So just.

So people aren't thinking hey, it's just going to be evenly split between the quarters, because we'll probably get.

We'll get a few more wells fracked in Threeq and Fourq you and then we'll we'll work on when we bring those on.

Okay got it and then just on midstream question, maybe for Michael do you have a commodity mix for the Wild basin downtime and does it look you know approximately like what wild basin looks like on a production mix or was it more gas weighted.

That number is specifically is a little bit more.

Gas weighted Brad we don't.

We know that the oil was impacted.

Well, we don't know exactly how much and so of that 3000, a day it could be a bit higher not too with the oil side, but more of that is going to be on on the gas side in terms of the way we thought about that.

Okay. Thanks.

But you're right that gas plant downtime did impact.

Potentially on the oil side as well.

And what we're trying to show is that with the July number is that your production numbers is back up and part of that is the plant running very efficiently now.

Our next question comes from Daniel Pickering, with TPH asset management. Please go ahead.

Good morning, guys.

Hey, Dan.

Michael or Tommy or Taylor.

Maintenance capital, how do you think about how much money you need to spend to sort of hold.

Volumes flat 20 versus 19 roughly.

So I think to start with wood.

Probably talk about is with the.

And Michael can can add to this but what the capital.

Program is going to look like we think going forward and.

It's.

It is probably.

Flat to slightly down from from this year and for 2020.

And in fact, it will fit.

It is probably pretty close to what's out there from a guidance perspective.

At this point then.

If I can add to that on the on the volume side.

Yes, so sedan I think that you will see kind of EUR 2019 guidance that consolidated numbers.

Is right around 850, and as Taylor mentioned next year that consolidated number should come down I think consensus has it just under 800.

I think thats, probably a good ballpark and that's on a consolidated basis.

And then.

I think Tom we talked about in his comments.

Fourth quarter oil volumes, we should be in a position to.

To keep that flat to growing a little bit.

Obviously, there is a lot of things that that depends on and we don't have a full program scoped out for 2020, yet but.

That's how we're thinking about it.

No.

Thanks, and then I guess conceptually I'm I'm looking at a stock market that doesn't.

Clearly isn't rewarding.

The assets, you've got or the spending program, you're doing or its not rewarding something it's obviously penalizing you for kind of where we sit today and I guess my question I heard on the call some.

Some kind of dancing around a little bit about the future of though MP.

I just wonder given how the market's treating the company now if there isn't.

You know if it didnt time for something a little more aggressive and how you guys think about.

Clearly undervalued equity and the levers that you can pull whether its capital spending Oh and PC monetization.

You know something isn't working now what changes going forward.

Yeah, Dan I think that.

You know the.

The good news in there is that whether you look at what we have in the Willis than what we have in the Delaware and what we have in MP, we've got a portfolio of coveted assets like I talked about earlier.

When we start thinking about the midstream and it it kind of.

There's a focus on wild basin, but it also on the waterside touches our entire footprint in the Williston, but.

But ultimately we do feel like there's a coveted asset there that.

Whether it's our covenant assets or somebody else's I mean, what you.

The coveted assets provide a lot optionality.

And so and you know as we've talked about.

As we move our drilling activity outside we've got that thing in place and as we move drilling activity outside of the Wild basin.

Complex.

It increases options.

For us is probably the easiest way to say that if that makes sense.

Yes, I mean, I guess I understand it increases optionality Tommy the.

<unk>, let's pretend that action comes on that front sometime in the next six months or so.

You'd have a lot of cash from some sort of monetization of that asset is what are the priorities for.

No external non operational cash is it is it paying down debt.

It seems like the market's nervous about your leverage are you nervous about your leverage would you pay down debt would you spend more on T., how would you handle that yeah, I think as we've talked about in the past than you know it's.

In today's world.

The.

Well you know what you've heard US say is when you look at debt metrics.

The old three is.

Is below two and it may be even one and a half [laughter].

And and I do think as we get screened that metric does.

Provide a bit of a drag.

And so as we've talked about.

In free cash flow.

Or available cash that's that's the first place that it needs to go to get right sized and in this market, which and I don't think thats going to change anytime soon Michael you got anything to add to that I think that's exactly right. So prioritization is paying down debt first and foremost thing.

No.

Okay. Thank you.

Thanks, Dan.

Our next question comes from David Deckelbaum with Cowen. Please go ahead.

Hi, Good morning, Tommy and Taylor, Thanks for taking the time.

You guys just provide a lot of really comprehensive answers to a lot of questions that I had but I really just wanted to add on to.

One.

Some of the the test outside I guess more in like the extended core going into.

Alger South Cottonwood area, I guess as you're evaluating these and you're looking at these areas kind of expanding.

Do you see these as opportunities to start allocating rigs towards or do you see these as opportunities to delineate some areas like foreman Butte that you would look to sell over time.

So.

Okay.

Really probably some of both and when you.

You look you look back at.

You remember after we did the.

Affords deal we went through a divestiture process sold about $306 million in assets and.

We originally talked about you know.

Looking at something around 500 million and we just.

At that time elected to.

Just go with what we thought was the very best value, but one of the things you saw at that time was.

While there was.

Some good test results with the.

Newer bigger completions.

Across the basin, they weren't long lived up to that point and they hadn't stretched as far as a they have right now so.

It it by our testing and third party testing both the.

Yes doing two things one is it pull more of this inventory into into the core and was economic at a at a low price points. So it really sets us up for.

Our continued drilling program as we go forward.

But in addition to that it really makes some of this acreage attractive.

That was.

Kind of further out and into Q and so we're excited about having more of those test push out on the acreage at the right time.

We are open to.

Placing those assets since my fans who.

Sees a lot of value and on that stuff, that's the tail in our inventory and helps us to.

To get our.

Good or debt down or levers as we just talked about and those are things that we'll be looking at but some of both.

I appreciate that.

I guess, we havent seen.

Ton of Bakken transactions outside of that I guess, some stuff in the first quarter.

I guess for obvious reasons, especially in the public Arena I guess.

Have you seen any interests on the I guess like has that has to make a mix of buyers changed that you're seeing out there that are kind of sniffing around deals right now.

Yeah. It was it is it more on the private side now or private equity side or are you still kind of seeing like the same players that would be out there.

Yeah, We obviously as you mentioned David that the Andy market is extremely challenged especially as you think about.

Public company buyers with the capital markets, where they are.

You've really seen that Andy market.

Shrink where you have seen.

Transactions done kind of more broadly.

There there has been a little bit more capital access on the private side and so that is where you've seen.

Some of the more recent more recent deals.

Thank you guys best of luck with everything I appreciate the time.

Thanks, Dave.

Our next question comes from Noel Parks with.

Coker and Palmer. Please go ahead.

Good morning.

I know.

I apologize if you touched on this already but could you just talk a little bit more about the nature of the downtime at Wild basin.

You know what.

Kind of a precipitating event was and whether it's our.

Something in hindsight was foreseeable or more of a random thing.

Yeah, we didn't talk specifically about the downtime no, but it's a good question look one of the things that I'd say is that we we saw a couple of years back.

A huge need for gas processing capacity in the basin as we move forward to building our second gas plant.

Knowing that the basin was going to be constrained.

Today, you've got 2.8 Bcf in the basin with with our plan in place 2.2 Bcf of processing capacity. So that all played out really well the other nice thing for us is that.

While we stress kind of safety and making sure that you can get your systems online and doing it safely we did that.

And we were on time and on budget with the plant which is.

Phenomenal success for for the team.

You have seen because of.

Or just the weather fluctuations kind of throughout a in a very short build season, a number of other plants.

It Didnt have the same type of success of getting up online like ours did we had some downtime. Some of that's just kind of what I would call. Some of that start up phase of of knocking out the kinks and it did it did impact impact us because of our concentration kind of in wild basin to that plant.

But kind of broader speaking getting that gas plant up online on time in December was was just a huge feat for the team and what I would call. This is just some of that initial startup that that that we got kind of six months into it.

Now we're through it and we think we're past it.

Yeah, you'd like to think that these things are all cookie cutter and you turn them on and they worked perfectly.

But they're a little bit more complex than that so you always know that you're going to have a little bit of.

You know whether its three months or six months trying to get these things.

Lined out and operating.

Correctly and efficiently and that's it's not.

Not a wild surprise you'd like you'd rather not have that but.

But it's not a wild surprise.

Okay, and just actually do.

Can you tell us what the.

How long the plant was down how many days.

It was about 20 days plus or minus so something like a few few weeks ballpark yes.

Okay, Great and then just trying to the Delaware for a minute I've heard some other operators out there comment on.

Our being in a.

In a window of opportunity where.

Meaningful acreage swaps and so forth.

Can still be accomplished but that that window might be closing I was just curious if I'm around your acreage do you have a sense of any urgency about that among your partners and competitors.

For or just with with oil having.

And then a little weaker lately is there certain not so much of a a press going on anymore.

Yeah, we we've.

Focused since since we got the assets you know a big part of the focus was to.

Just really blocking up and do bolt ons and we've been successful on that front we've done.

A number of trades and done some small acquisitions that.

Has resulted in.

Extending the number of places we drilled two mile laterals that was already high numbers kind of 70, 580% of the acreage and so we're moving that.

Continue to move that up and then.

Consolidating in around the acreage we've been successful so we've seen.

You know good cooperation and willingness to do both trades and where it makes sense to.

To to sell assets that are.

Core to people or may not be an exact fit for.

For their position.

That may not be concentrated in this area. So we've been been pleased on that front.

Did you know it looks like you were going to continue to have those opportunities going forward.

Just to clarify but is your sense that we're kind of in the final innings of that process or just something that's going to keep going yeah. No. It look it's actually if anything kind of that trade activity in bolt on.

Is if anything maybe picked up a bit.

As everybody starts to optimize their capital spend and focus on their operated projects, especially with lease terms in the in the within the.

In the Delaware that you're very familiar with.

Very.

Very different than the Williston basin for instance.

With different clauses that you have in these leases.

So is it.

With the combination of those clauses.

In the leases as well as people being focused on there.

Operated programs and optimizing their capex.

If anything I would say that it's made it that I mean, it's doing trades is never easy.

But at least the.

So people are.

Are feeling the need to to consolidate which.

And as I mentioned I mean, we just picked up some acreage that allowed us to form a 12 80, where we didnt have it before and.

But it does.

It does tend to get people focused on it.

Great. Thanks, a lot you bet.

This concludes our question and answer session.

I would now like to turn the conference back over to Tommy News for any closing remarks.

Thanks.

In closing Oasis continues to execute its 2019 program.

We remain committed to being free cash flow neutral to positive in a volatile oil price environment as we have since 2015, but I want to be clear, we're focused on making prudent long term value decisions.

For our shareholders.

Again, thanks for joining our call.

The conference is now concluded. Thank you for attending today's presentation you may now disconnect.